Accelerating the exploration and development of deep shale gas is of great significance to ensure national energy security and achieve the dual carbon targets. In the high-temperature and high-pressure environment of deep shale buried below 3500m , the nanopores are more developed, and the gas in the restricted space will exist in the form of "solid-like dense accumulation", which is much denser than the density of free gas. In addition, as the pore size decreases, the thermodynamic parameters of methane will also change, and the phase characteristics of methane stored in different shale pores vary greatly. How to accurately describe and quantitatively characterize the adsorbed and free gas in deep shale reservoirs is a difficult problem in the exploration and development of deep shale gas, which is directly related to the evaluation and calculation of deep shale gas resource potential, the screening of favorable target areas and the formulation of development plans, and is also the basis for the scientific and efficient development of deep shale gas reservoirs.

Recently, a research team led by Associate Professor Weijun Shen from the Institute of Mechanics of the Chinese Academy of Sciences (IMCAS), conducted the collaborative studies on the quantitative characterization of adsorbed and free gas in deep shales with Sinopec Research Institute of Petroleum Engineering, China University of Mining and Technology, etc. To address this problem, deep shales from the Longmaxi Formation in southern China were collected to conduct high-pressure isothermal adsorption experiments. The adsorption behavior of methane in deep shales was analyzed, and the adsorbed gas and free gas in the deep shales were characterized quantitatively. The effects of temperature, pressure, and moisture on the adsorbed gas and the density of the free gas were discussed. The results indicated that the excess adsorption isotherm curve for methane in deep shales increased and then decreased with the increase of pressure, and the modified Langmuir adsorption model may be used to describe the high-pressure adsorption behavior. The adsorbed gas in shales decreases gradually with the increase of pressure, and the proportion of adsorbed gas and free gas is between 23 and 74% when the pressure reaches 50 MPa. This research provides a useful reference for explaining how to best evaluate shale gas reservoirs, estimate the reserves in deep shales, and evaluate the adsorption and flow capacity of deep shale gas.

Fig.1 Excess adsorption fitting results for the model in deep shales

Fig. 2 Volumetric model of deep shale gas and gas content versus pressure

Fig. 3 Ratio of adsorbed and free gas versus pressure

    The work was published in Energy & Fuels (2023, 37: 3752-3759), which is titled of "Quantitative studies on the characterization and evaluation of adsorbed gas and free gas in deep shale reservoirs". The first author and corresponding author is Weijun Shen, Associate Professor of Institute of Mechanics, Chinese Academy of Sciences. The co-authors are from Sinopec Research Institute of Petroleum Engineering, China University of Mining and Technology, and Dalian University of Technology, etc. This work was supported by the National Natural Science Foundation of China (No. 12172362), the China National Petroleum Corporation (CNPC) Innovation Foundation (2021DQ02-0204), and the Youth Innovation Promotion Association of the Chinese Academy of Sciences.